Enhanced oil recovery (sometimes also called tertiary oil recovery) is the description applied by the oil industry to non-conventional techniques for getting more oil out of subsurface reservoirs than is possible by natural production mechanisms (primary oil recovery) or by the injection of water or gas (secondary oil recovery).
If oil is to move through the reservoir rock to a well, the pressure under which the oil exists in the reservoir must be greater than that at the well bottom. The rate at which the oil moves towards the well depends on a number of features, among which the pressure differential between the reservoir and the well, permeability of the rock, layer thickness and the viscosity of the oil. The initial reservoir pressure is usually high enough to lift the oil from the producing wells to the surface, but as the oil is produced, the pressure decreases and the production rate starts to decline. Production, although declining, can be maintained for a time by naturally occurring processes such as expansion of the gas in a gas cap, gas release by the oil and/or the influx of water. A more extensive description of natural production mechanisms can be found in the Petroleum Handbook, 6th edition, Elsevier, Amsterdam/New York, 1983, p. 91–97.
The oil not producible, or left behind, by the conventional, natural recovery methods may be too viscous or too difficult to displace or may be trapped by capillary forces. Depending on the type of oil, the nature of the reservoir and the location of the wells, the recovery factor (the percentage of oil initially contained in a reservoir that can be produced by natural production mechanisms) can vary from a few percent to about 35 percent. Worldwide, primary recovery is estimated to produce on average some 25 percent of the oil initially in place.
In order to increase the oil production by natural production mechanisms, techniques have been developed for maintaining reservoir pressure. By such techniques (also known as secondary recovery) the reservoir's natural energy and displacing mechanism which is responsible for primary production, is supplemented by the injection of water or gas. However, the injected fluid (water or gas) does not displace all the oil. An appreciable amount remains trapped by capillary forces in the pores of the reservoir rock and is bypassed. This entrapped oil is known as residual oil, and it can occupy from 20 to 50 percent, or even more, of the pore volume. See for a more general description of secondary recovery techniques the above-mentioned Petroleum Handbook, p. 94–96.
Enhanced oil recovery (sometimes called tertiary oil recovery) is the description applied by the oil industry to non-conventional techniques for getting more oil out of subsurface reservoirs than is possible by natural production mechanisms or secondary production mechanisms. Many enhanced oil recovery techniques are known. It covers techniques as thermal processes, miscible processes and chemical processes. Examples are heat generation, heat transfer, steam drive, steam soak, polymer flooding, surfactant flooding, the use of hydrocarbon solvents, high-pressure hydrocarbon gas, carbon dioxide and nitrogen. See for a more general description of secondary recovery techniques the above-mentioned Petroleum Handbook, p. 97–110.
The use of nitrogen in enhanced oil recovery processes is well known. At first waste gases as stack gas, flue gas and exhaust gas were used. These gasses usually contained not only nitrogen, but also carbon dioxide and optionally steam. See for instance U.S. Pat. No. 4,499,946. A problem, however, was the presence of certain waste products such as nitrogen oxides and sulphur oxides which give rise to corrosion and pollution problems. A paper by M. D. Rushing et al., entitled “Miscible Displacement with Nitrogen”, Petroleum Engineer, November 1977, p. 26–30, describes a miscible oil displacement process involving the injection of high pressure nitrogen. As disclosed, pure nitrogen is injected into the reservoir and functions to initially strip relatively low molecular weight hydrocarbons from the reservoir oil. U.S. Pat. No. 4,434,852 describes the use of nitrogen and 2 to 20 percent by volume of light hydrocarbons in the enhanced oil recovery of subterranean oil reservoirs. Mixtures of nitrogen and carbon dioxide are described in U.S. Pat. Nos. 3,811,501 and 4,008,764. The injected gas may take the form of substantially pure nitrogen, such as produced by cryogenic fractionation of air as described by Rothrock et al., Nitrogen Floods Need Specialise Surface Equipment, Petroleum Engineer, August 1977, p. 22–26. As described above, the nitrogen gas may also take the form of flue gasses such as from boilers or internal combustion engines which typically will contain about 80–90% nitrogen, usually 88%, 5–15% carbon dioxide, usually 10%, 0–2% carbon monoxide, usually 1%, and the remainder hydrogen and trace amounts of other gasses.
As described, attention has been given to producing nitrogen cryogenically. A problem, however, is the need of a large, expensive cryogenic unit.
Several cryogenic concepts have been developed over the years to liquefy and separate air into its main constituents nitrogen, oxygen and rare gases. Refrigeration for cryogenic applications is produced by absorbing or extracting heat at low temperature and rejecting it to the atmosphere at higher temperatures. Three general methods for producing cryogenic refrigeration in large-scale commercial application are the liquid vaporisation cycle, the Joule-Thomson expansion cycle and the engine expansion cycle. The first two are similar in that they both utilise irreversible isenthalpic expansion of a fluid, usually through a valve. Expansion in an engine approaches reversible isenthalpic expansion with the performance of work. For more detailed discussion reference is made to Perry's Chemical Engineers Handbook, Sixth Edition, 12–49 ff. (McGraw-Hill, New York, 1984), Kirk-Othmer, Encyclopedia of Chemical Technology, Fourth Edition, Volume 7, p. 662 ff. (John Wiley and Sons, New York, 1993) and Ullmann's Encyclopedia of Industrial Chemistry, Fifth Edition, Volume A 18, p. 332 ff. (VCH, Weinheim, 1991).
Most commercial air separation plants are based on Linde's double distillation column process. This process is clearly described in the above references. In a typical example, feed air is filtered and compressed to a pressure usually between 5 and 10 bara. The compressed air is cooled and any condensed water is removed in a separator. To avoid freezing of water and carbon dioxide in the cryogenic part of the plant, the feed air is further passed through an adsorbent bed, usually activated alumina and/or molecular sieves, to remove the last traces of water and carbon dioxide. The purified air is than cooled down further, and fed to a first cryogenic distillation unit, usually at an intermediate stage. Crude liquid material from the bottom section of the first distillation unit, usually comprising between 40 and 50 mol percent oxygen, is fed to the second distillation unit (which second unit is usually on the top of the first distillation unit, the condenser of the first column usually acting as the reboiler for the second unit), usually also at an intermediate stage. The second distillation unit is operated at relatively low pressure (usually 1 to 2 bara). At the top of the first distillation unit almost pure liquid nitrogen is obtained which is typically fed to the second column at the top. Pure liquid oxygen is obtained at the bottom of the second distillation unit, while pure gaseous nitrogen is obtained from the top of the second column.
Many variations on the above concept are known. These include separation of air into gaseous products, liquid products and all kind of combinations thereof. Also the production of partly enriched oxygen and/or nitrogen streams together with almost pure oxygen and/or nitrogen streams, either in liquid or gaseous phase is well known. In addition there may be additional distillation units to separate any of the rare gases present in the feed air. Further, the methods for creating the low temperatures may vary in many ways. In this respect reference is made to the above cited literature references, and further to EP 798524, JP 08094245, EP 593703, EP 562893, U.S. Pat. No. 5,237,822, JP 02052980, EP 211957, EP 102190, SU 947595 JP 71020126 and JP 71020125.
The nitrogen produced in an air separation unit is usually vented to the atmosphere. This is at least partly due to the fact that, especially gas-to-liquids, plants (using so called stranded gas) are usually at remote locations, far away from industrial activities which could use the nitrogen. Up till now no suggestion has been made to use the nitrogen for enhanced oil recovery, while there are sufficient locations at which the nitrogen produced in the air separation unit could be used for enhanced oil recovery. This is the more remarkable as several suggestions have been made as to the use of other side products from gas-to-liquids plants, as energy and water.
Many publications are known describing processes for the conversion of (gaseous) hydrocarbonaceous feed stocks, as methane, natural gas and/or associated gas, into liquid products, especially methanol and liquid hydrocarbons, particularly paraffinic hydrocarbons. In this respect often reference is made to remote locations (e.g. in the dessert, tropical rairi-forest) and/or offshore locations, where no direct use of the gas is possible, usually due to the absence of large populations and/or the absence of any industry. Transportation of the gas, e.g. through a pipeline or in the form of liquefied natural gas, requires extremely high capital expenditure or is simply not practical. This holds even more in the case of relatively small gas production rates and/or fields. Reinjection of gas will add to the costs of oil production, and may, in the case of associated gas, result in undesired effects on the crude oil production. Burning of associated gas has become an undesired option in view of depletion of hydrocarbon sources and air pollution. Gas found together with crude oil is known as associated gas, whereas gas found separate from crude oil is known as natural gas or non-associated gas. Associated gas may be found as “solution gas” dissolved within the crude oil, and/or as “gas cap gas” adjacent to the main layer of crude oil. Associated gas is usually much richer in the larger hydrocarbon molecules (ethane, propane, butane) than non-associated gas.
In WO 91/15446 a process is described to convert natural gas, particularly remote location natural gas (including associated gas), into liquid hydrocarbons suitable for use as fuel. However, no optimally integrated, efficient, low-cost process scheme has been described. In WO 97/12118 a method and system for the treatment of a well stream from an offshore oil and gas field has been described. Natural gas is converted into syngas using pure oxygen in an autothermal reformer, a combination of partial oxidation and adiabatic steam reforming. The syngas (comprising a considerable amount of carbon dioxide) is converted into liquid hydrocarbons and wax. No fully and optimally integrated process scheme for a highly efficient, low capital process is described in this document.
In EP 1 004 746 a process has been described for the combined production of liquid hydrocarbons and the recovery of oil from a subsurface reservoir by partial oxidation of natural gas followed by conversion of the synthesis gas thus obtained into hydrocarbons and separating the hydrocarbons into liquid hydrocarbons and gaseous hydrocarbons (mainly C1–C4 hydrocarbons), and combusting and/or expanding these gaseous hydrocarbons to provide power for the secondary or enhanced recovery of oil. However, a further optimisation of the efficiency and the integration of the process is desired.
The present invention is directed to a process for the recovery of oil from a subsurface reservoir in combination with the production of liquid hydrocarbons from a hydrocarbonaceous stream, comprising:
(i) separating an oxygen/nitrogen mixture into a stream enriched in oxygen and an oxygen depleted stream;
(ii) partially oxidating the hydrocarbonaceous feed at elevated temperature and pressure using enriched oxygen produced in step (i) to produce synthesis gas;
(iii) converting synthesis gas obtained in step (ii) into liquid hydrocarbons;
(iv) recovering oil from a subsurface reservoir using at least part of the oxygen depleted gas stream produced in step (i).